Method of fracturing a subterranean formation using micronized barite particles

ABSTRACT

A drilling fluid composition that contains micronized barite particles with a particle size in the range of 1 to 5 μm, and also a method of fracturing a subterranean formation using the drilling fluid composition. Various embodiments of the micronized barite particles and the method of making thereof, the drilling fluid composition, and the method of fracturing a subterranean formation are also provided.

CROSS REFERENCE TO RELATED APPLICATIONS

This application s based on, and claims the benefit of priority to,provisional application No. 62/274,423 filed Jan. 4, 2016, the entirecontents of which are incorporated herein by reference.

BACKGROUND OF THE INVENTION

Technical Field

The present invention relates to a drilling fluid composition thatcontains micronized barite particles as a weighting agent, and also amethod of fracturing a subterranean formation using the drilling fluidcomposition.

Description of the Related Art

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, are neitherexpressly or impliedly admitted as prior art against the presentinvention.

Drilling fluids or muds are used in the rotary drilling process of wellsto tap underground collections of oil and gas. These muds have severalfunctions. The most important functions are to assist in the removal ofcuttings from the well, to seal off unwanted formations which may beencountered at different levels preventing the loss of drilling fluidsto void spaces and to permeable or porous formations, to lubricate thedrilling tool, to maintain the well bore pressure and stability of thebore hole, and to hold the cuttings in the suspension during events ofshutdowns in drilling.

Drilling fluid additives form a thin, low permeability filter cake (mudcake) over time that seals openings in formations to reduce the unwantedinflux of fluids into permeable formations. A mud cake forms when thedrilling fluid contains particles that are approximately the same sizeas or have diameters greater than about one third of the pore diameter(or the width of any opening such as induced fractures) in the formationbeing drilled. The drilling fluid must circulate in the wellbore (downthe drill pipe and back up the annulus) to perform the above mentionedfunctions for the drilling process to continue smoothly. Therefore, thedrilling fluid must remain in the wellbore all the time in order tocontrol and prevent caving of the wellbore.

Drilling fluid compositions generally include one or more weightingagents such as barite, iron oxides, manganese tetraoxide, potassiumformate, hematite, and calcium carbonate, etc. to increase the overalldensity of the drilling fluid so that sufficient bottom hole pressurecan be maintained thereby preventing an unwanted influx of formationfluids.

Barite is one of the most common weighting agents used in drillingfluids, completion fluids, cementing fluids, etc. in deep oil and gaswells. Generally, the barite particle size used in drilling fluid rangesfrom 30 to 70 μm. The invasion of the mud filtrate due to the pressuredifference will create mud cake that mainly composed of barite havingparticle size of 30 to 70 μm, which can cause barite scale formation andfurther reduce the reservoir permeability. Additionally, it was shownthat barite particles facilitate the formation of barite scales aroundcasing and production tubing, yet cause erosion of surface chokes andvalves. Consequently, the process of removing the mud cake (filter cake)and/or barite scales could be very costly, particularly in horizontalreservoirs and extended reach wells, when barite particles with aparticle size of 30 to 70 μm is used as the weighting agent in theformulation of the drilling fluid.

In view of the forgoing, one objective of the present invention is toprovide a drilling fluid composition that contains micronized bariteparticles as a weighting agent, and to provide a method of fracturing asubterranean formation using the drilling fluid composition.

BRIEF SUMMARY OF THE INVENTION

According to a first aspect, the present disclosure relates to a methodof fracturing a subterranean formation, involving i) injecting adrilling fluid composition into the subterranean formation through awellbore to fracture the subterranean formation and form fissures in thesubterranean formation, wherein the drilling fluid composition includesa) micronized barite particles with a particle size in the range of 1 to5 μm, b) an aqueous base fluid, c) a viscosifier, wherein the micronizedbarite particles are present in the drilling fluid composition at aconcentration in the range of 1 wt % to 50 wt %, relative to the totalweight of the drilling fluid composition.

In one embodiment, the method of fracturing further involves injecting aproppant into the subterranean formation through the wellbore to depositthe proppant in the fissures.

In one embodiment, the method of fracturing further involves circulatingthe drilling fluid composition within the wellbore after injecting thedrilling fluid composition.

In one embodiment, the drilling fluid composition is injected at apressure of at least 5,000 psi to fracture the subterranean formation.

In one embodiment, the viscosifier is bentonite.

In one embodiment, the drilling fluid composition has a plasticviscosity of 14 to 18 cP at a temperature of 80 to 90° F.

In one embodiment, the drilling fluid composition has a plasticviscosity of 4.5 to 7.0 cP at a temperature of 200 to 280° F.

In one embodiment, the drilling fluid composition has a density of 12 to14 ppg at a temperature of 80 to 90° F.

In one embodiment, the drilling fluid composition has a yield point of35 to 45 lb/100 ft² at a temperature of 80 to 90° F.

In one embodiment, the drilling fluid composition has a gel strength of15 to 25 lb/100 ft² at a temperature of 80 to 90° F., after 10 seconds.

In one embodiment, the drilling fluid composition has a yieldpoint-to-plastic viscosity ratio of 2.5 to 4.5.

In one embodiment, the drilling fluid composition has a zeta potentialof 55 to 65 mV.

In one embodiment, a solubility of the micronized barite particles inthe aqueous base fluid is at least 70 g/100 g at a temperature of 150 to250° F.

In one embodiment, the drilling fluid composition further includes atleast one additive selected from the group consisting of an antiscalant,a thickener, a deflocculant, an anionic polyelectrolyte, a lubricant,and a fluid loss additive.

According to a second aspect, the present disclosure relates to a methodof making micronized barite particles, involving i) stirring asuspension solution comprising a barite mixture and at least onechelating agent, ii) filtering the suspension solution to form a filtercake comprising barite, iii) grinding the filter cake to form themicronized barite particles each having a particle size in the range of1 to 5 μm, wherein an amount of barite in the barite mixture is at least80wt %, and wherein an amount of said chelating agent in the suspensionsolution is in the range of 1wt % to 20wt %, relative to the totalweight of the suspension solution.

In one embodiment, the method of making the micronized barite particlesfurther involves grinding the barite mixture prior to the stirring.

In one embodiment, the suspension solution is centrifugally stirred witha rotational speed of at least 500 rpm, at a temperature in the range of40 to 80° C.

In one embodiment, the amount of barite in the barite mixture is atleast 95wt %, wherein the amount of the chelating agent in the solutionis in the range of 1wt % to 10wt %.

In one embodiment, the chelating agent is at least one selected from thegroup consisting of ethylenediamine tetraacetic acid, glutamic diaceticacid, hydroxyethylenediamine triacetic acid, and salts thereof.

In one embodiment, the suspension solution has a pH in the range of 7 to14.

The foregoing paragraphs have been provided by way of generalintroduction, and are not intended to limit the scope of the followingclaims. The described embodiments, together with further advantages,will be best understood by reference to the following detaileddescription taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the disclosure and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 is schematic of a lab-scale setup for making micronized bariteparticles.

FIG. 2 represents a zeta potential of a drilling fluid composition thatincludes micronized barite particles versus a zeta potential of adrilling fluid composition that includes commercial barite particles.

FIG. 3 is schematic of pressurizing a drilling fluid composition,wherein a barite filter cake is produced.

FIG. 4 is schematic of removing the barite filter cake.

FIG. 5 represents a solubility of the micronized barite particles versusthat of the commercial barite particles in a solution that contains 20%of K₅DTPA (pH=11) at 200° F.

FIG. 6 represents a rheometer reading (Fann reading) of a drilling fluidcomposition that includes micronized barite particles versus a rheometerreading of a drilling fluid composition that includes commercial bariteparticles, at room temperature (i.e. about 85° F.).

FIG. 7 represents a plastic viscosity of a drilling fluid compositionthat includes micronized barite particles versus a plastic viscosity ofa drilling fluid composition that includes commercial barite particles,at different temperatures.

FIG. 8 represents a yield point of a drilling fluid composition thatincludes micronized barite particles versus a yield point of a drillingfluid composition that includes commercial barite particles, atdifferent temperatures.

DETAILED DESCRIPTION OF THE EMBODIMENTS

According to a first aspect, the present disclosure relates to a methodof fracturing a subterranean formation, involving injecting a drillingfluid composition into the subterranean formation through a wellbore tofracture the subterranean formation and form fissures in thesubterranean formation.

“Fracturing” or “fracking” as used herein refers to the process ofinitiating and subsequently propagating a fracture of the rock layer byemploying the pressure of a fluid as the source of energy. In someembodiments, fracking is accomplished by pumping in liquids at highpressure. A hydraulic fracture may be formed by pumping a fracturingfluid (i.e. the drilling fluid composition, in one or more of itsembodiments) into the wellbore at a rate sufficient to increase thepressure downhole to a value in excess of a critical fracture pressureassociated with the formation rock. The pressure causes the formation tocrack, allowing the fracturing fluid to enter and extend the crackfarther into the formation. Following fracking by high pressures, thefractured formation allows more hydrocarbons (e.g., methane, condensate,ethane, oil) and/or water to be extracted since the formation walls aremore porous. The fracking may be performed on new wells or wells withpoor production. Fracking can be done in vertical wells, slanted wells,and in horizontally drilled wells.

As used herein, a “wellbore” includes any geological structure orformation, that may contain various combinations of natural gas (i.e.,primarily methane), light hydrocarbon or non-hydrocarbon gases(including condensable and non-condensable gases), light hydrocarbonliquids, heavy hydrocarbon liquids, crude oil, rock, oil shale, bitumen,oil sands, tar, coal, and/or water. Exemplary non-condensable gasesinclude hydrogen, carbon monoxide, carbon dioxide, methane, and otherlight hydrocarbons.

In one embodiment, the drilling fluid composition is injected at apressure of at least 5,000 psi, at least 5,500 psi, at least 6,000 psi,at least 6,500 psi, at least 7,000 psi, at least 7,500 psi, but no morethan 10,000 psi to fracture the subterranean formation and form fissuresin the subterranean formation.

In one embodiment, the method of fracturing further involves circulatingthe drilling fluid composition within the wellbore after injecting thedrilling fluid composition. In one embodiment, the drilling fluidcomposition is circulated for at least 30 minutes, preferably at least45 minutes, more preferably at least 60 minutes.

In one embodiment, the method of fracturing further involves injecting aproppant into the subterranean formation through the wellbore to depositthe proppant in the fissures and to maintain the structural integrity ofthe wellbore. A “proppant” as used herein refers to any granularmaterial that, in an aqueous mixture, can be used to fracture the rockformation and to provide structural support to the wellbore and/orfissures that develop in the rock formation due to pressurizing the rockformation during fracking. In one embodiment, the proppant is grains ofsand, ceramic, silica, quartz, or other particulates that prevent thefractures from closing when the injection is stopped.

The drilling fluid composition, which is injected into the subterraneanformation, includes micronized barite particles.

Barite (i.e. barium sulfate, BaSO₄) is a dense mineral used as aweighting agent in drilling fluid compositions with a specific gravityin the range of 4.20 to 4.50 g/cm³. The term “micronized bariteparticles” as used herein refers to homogenized barite particles with amean particle size in the range of 1 to 5 μm, preferably 1 to 4 μm, morepreferably 1 to 3 μm, which are used as weighting agents to increase adensity of the drilling fluid composition to at least 12 ppg (pounds pergallon), preferably at least 12.5 ppg. In a preferred embodiment, lessthan 1 wt %, preferably less than 0.5wt % of a given amount of themicronized barite particles includes barite particles with a particlesize of less than 1 micron. Furthermore, in another preferredembodiment, less than 2wt %, preferably less than 1.5wt %, preferablyless than 1wt % of a given amount of the micronized barite particlesincludes barite particles with a particle size of greater than 5 micron.Accordingly, in a preferred embodiment, at least 95wt %, preferably atleast 96wt %, preferably at least 97wt %, preferably at least 98wt %,preferably at least 99wt %, of a given amount of the micronized bariteparticles includes barite particles with a particle size in the range of1 to 5 μm. In one embodiment, the amount of barite particles in the“micronized barite particles” is at least 99wt %, preferably at least99.5wt %, preferably at least 99.9wt %, wherein no more than 1wt %,preferably no more than 0.5wt %, preferably no more than 0.1wt % of the“micronized barite particles” may include impurity particles such asbauxite, bentonite, dolomite, limestone, calcite, vaterite, aragonite,magnesite, taconite, gypsum, quartz, marble, hematite, siderite,ilmenite, limonite, magnetite, andesite, garnet, basalt, dacite,nesosilicates or orthosilicates, sorosilicates, cyclosilicates,inosilicates, phyllosilicates, tectosilicates, kaolins, montmorillonite,fullers earth, and halloysite, and the like. According to thisembodiment, the size of the impurity particles may be in the range of0.5 to 10 μm, preferably 1 to 8 μm, more preferably 1 to 5 μm.

In one embodiment, barite present in the micronized barite particles arelocal Saudi barite. A given amount of an untreated and unprocessed localSaudi barite includes at least 90wt %, preferably at least 95wt % ofbarite (i.e. BaSO₄), less than 5wt %, preferably less than 4wt % ofsilica (i.e. SiO₂), and less than 1wt %, preferably less than 0.5wt % ofeach of SrSO₄, Fe₂O₃, MgO, CaO, Al₂O₃, and traces amount of impuritiessuch as calcite, gypsum, dolomite sulfur, halloysite, calcium carbonate,quartz, venniculite, and hematite. The composition of local Saudi baritemay preferably be different than the composition of commercially bariteore extracted from other geographical areas, as a given amount of localSaudi barite includes at least 90wt %, preferably at least 95wt % ofbarite.

In a preferred embodiment, the micronized barite particles are presentin the drilling fluid composition at a concentration in the range of 1wt% to 80wt %, preferably 5wt % to 70w t%, preferably 10wt % to 60wt %,preferably 15wt % to 50wt %, preferably 20wt % to 50wt %, preferably25wt % to 50wt %, preferably 30wt % to 50wt %, preferably 35wt % to 50wt%, relative to the total weight of the drilling fluid composition.

The drilling fluid composition further includes an aqueous base fluid.The aqueous base fluid may refer to any water containing solution,including saltwater, hard water, and fresh water. For purposes of thisdescription, the term “saltwater” will include saltwater with a chlorideion content of between about 6000 ppm and saturation, and is intended toencompass seawater and other types of saltwater including groundwatercontaining additional impurities typically found therein. The term “hardwater” will include water having mineral concentrations between about2000 mg/L, and about 300,000 mg/L. The term “fresh water” includes watersources that contain less than 6000 ppm, preferably less than 5000 ppm,preferably less than 4000 ppm, preferably less than 3000 ppm, preferablyless than 2000 ppm, preferably less than 1000 ppm, preferably less than500 ppm of salts, minerals, or any other dissolved solids. Salts thatmay be present in saltwater, hard water, and/or fresh water may be, butare not limited to, cations such as sodium, magnesium, calcium,potassium, ammonium, and iron, and anions such as chloride, bicarbonate,carbonate, sulfate, sulfite, phosphate, iodide, nitrate, acetate,citrate, fluoride, and nitrite. The aqueous base fluids are ordinarilyclassified as saltwater fluids when they contain over 1% salt (about6000 ppm of chloride ion). In one embodiment, the aqueous base fluid ispresent in at least 40 wt % relative to the total weight of the drillingfluid composition, preferably at least 50%, preferably at least 60%,preferably at least 70%, preferably at least 80%, preferably at least90%.

In one embodiment, a solubility of the micronized barite particles inthe aqueous base fluid is at least 70 g/100 g, preferably at least 80g/100 g, preferably at least 90 g/100 g at a temperature of 150 to 250°F., preferably 200° F. Accordingly, the solubility of the micronizedbarite particles in the aqueous base fluid at a temperature of 200° F.is increased by at least 10%, preferably at least 20%, preferably atleast 30% when compared to that of a drilling fluid composition that issubstantially the same having barite particles with a particle size of40 to 70 μm.

The drilling fluid composition further includes a viscosifier. Exemplaryviscosifiers include, but are not limited to bauxite, bentonite,dolomite, limestone, calcite, vaterite, aragonite, magnesite, taconite,gypsum, quartz, marble, hematite, limonite, magnetite, andesite, garnet,basalt, dacite, nesosilicates or orthosilicates, sorosilicates,cyclosilicates, inosilicates, phyllosilicates, tectosilicates, kaolins,montmorillonite, fullers earth, and halloysite and the like. In oneembodiment, the viscosifier is present in an amount of 0.1 to 30 wt %,preferably 0.1 to 25 wt %, preferably 0.1 to 20 wt %, preferably 0.1 to15 wt %, preferably 0.1 to 10 wt %, preferably 0.5 to 5 wt %, relativeto the total weight of the drilling fluid composition.

In a preferred embodiment, the viscosifier is bentonite. Bentonite is anabsorbent aluminum phyllosilicate, impure clay consisting primarily ofmontinorillonite. Montmorillonite generally comprises sodium, calcium,aluminum, magnesium, and silicon, and oxides and hydrates thereof. Othercompounds may also be present in the bentonite of the presentdisclosure, including, but not limited to, potassium-containingcompounds, and iron-containing compounds. There are different types ofbentonite, named for the respective dominant element, such as potassium(K), sodium (Na), calcium (Ca) and aluminum (Al). Therefore, in terms ofthe present disclosure “bentonite” may refer to potassium bentonite,sodium bentonite, calcium bentonite, aluminum bentonite, and mixturesthereof, depending on the relative amounts of potassium, sodium,calcium, and aluminum in the bentonite. In one embodiment, the bentoniteis present in 0.1 to 10 wt % relative to the total weight of thedrilling fluid composition, preferably 0.1 to 5 wt %, preferably 0.1 to2 wt %, preferably 0.1 to 1.5 wt %, preferably 0.5 to 1.0 wt %.

Thorough mixing of the aqueous base fluid, the micronized bariteparticles, and the bentonite is desirable to avoid creating lumps or“fish eyes.” Preferably, the micronized barite particles are thoroughlymixed with the aqueous base fluid, and the viscosifier (e.g. bentonite)is added to the mixture thereafter. To avoid lumps or “fish eyes” thedrilling fluid composition may be stirred with a stirring speed of 1-800rpm, or 2-700 rpm, or 3-600 rpm. In one embodiment, the variousingredients of the drilling fluid composition (the micronized bariteparticles, the aqueous base fluid, and the viscosifier) are mixed for asufficient period of time to allow for hydration of the bentonite clayin the aqueous base fluid, and this period of time is usually betweenabout 5 and about 60 minutes, preferably between about 10 and about 40minutes, preferably between about 20 and about 30 minutes. Other mixingtimes may be also utilized to make the drilling fluid composition (e.g.less than 5 minutes, or more than 60 minutes) so long as the drillingfluid composition is substantially free of lumps.

In a preferred embodiment, the micronized barite particles are mixedwith the aqueous base fluid via a roll-milling mixer. A thorough mixingof the micronized barite particles with the aqueous base fluid may beprovided via a roll-milling mixer, without formation of lumps or “fisheyes”. In one embodiment, the micronized barite particles are sonicatedafter being mixed with the aqueous base fluid, but prior to beroll-milled.

In one embodiment, the pH of the drilling fluid composition may beadjusted depending on the drilling application or problems that may beencountered during a drilling operation. For example, the pH of thedrilling fluid composition may be adjusted so as to provide forpreferable solubility of the various organic components in thedispersion (e.g. organic components from the micronized bariteparticles, the preservative, the stabilizing agent, the antiscalant, thethickener, etc.) and is preferably between about 7 and 14, preferablybetween about 8 and 12, more preferably between about 10 and 12, morepreferably between about 10 and 11. This pH range may also beadvantageously suited for drilling operations where acid promoteddamage/corrosion to equipment, such as metal equipment is a concern. Inone embodiment, the pH of the drilling fluid composition is betweenabout 1 and 8, preferably 2 and 7, more preferably 3 and 6. This pHrange may be advantageously suited for drilling applications where scaleformation is particularly problematic for example. Various acids (e.g.citric acid, phosphoric acid, hydrochloric acid, etc.), bases (e.g.hydroxide bases, carbonate bases, amine bases, etc.), and buffers (e.g.monosodium phosphate, disodium phosphate, sodium tripolyphosphate, etc.)may be used to buffer or to adjust the pH of the drilling fluidcomposition, and such acids, bases, and buffers are known to those ofordinary skill in the art.

American Petroleum Institute (API) specifications of the drilling fluidcompositions that include the aqueous base fluid, the micronized bariteparticles, and the viscosifier determined using a Fann viscometer (or aV-G meter). The drilling fluid compositions are prepared after mixingthe drilling fluid compositions for 20 minutes, overnight aging, andstirring for 25 an additional five minutes. The Fann meter is used todetermine standard drilling fluid parameters as follows:

Plastic viscosity (PV, cp)=600 dial (i.e. rpm reading)−300 dial

Yield point (YP, lb/100ft²)=300 dial−plastic viscosity

Gel Strength (GS, lb/100ft²) is measured by taking a 3 rpm reading,allowing the drilling fluid composition to set for 10 seconds or for 10minutes or for 30 minutes. A difference in these readings between about1 and 8 is preferred.

It should be recognized that the above parameters are interrelated, andonce an acceptable plastic viscosity has been obtained, the other valuesmay be adjusted by adjusting the proportions of the micronized bariteparticles, the viscosifier, and other additives.

In one embodiment, the drilling fluid composition has a plasticviscosity of 14 to 18 cP, preferably 15 to 17 cP, preferably about 16 cPat a temperature of 80 to 90° F., preferably about 85° F.

In another embodiment, the drilling fluid composition has a plasticviscosity of 4.5 to 7.0 cP, preferably 4.5 to 6.5 cP, preferably 5 to6.5 cP, at a temperature of 200 to 280° F., preferably 200 to 250° F.Accordingly, the plastic viscosity of the drilling fluid composition ata temperature of 200 to 280° F., preferably 200 to 250° F. is reduced byat least 50%, preferably at least 55%, more preferably at least 60% whencompared to a drilling fluid composition that is substantially the samehaving barite particles with a particle size of 40 to 100 μm, preferably40 to 80 μm, preferably 40 to 70 μm, which has a plastic viscosity of 10to 12 cP, preferably 10 to 10.5 cP, at a temperature of 200 to 280° F.,preferably 200 to 250° F.

In one embodiment, the drilling fluid composition has a yield point of35 to 45 lb/100 ft², preferably 35 to 45 lb/100 ft² at room temperature(i.e. a temperature of 80 to 90° F., preferably about 85° F.).Accordingly, the yield point of the drilling fluid composition at roomtemperature is lower by about 1.0 lb/100 ft², preferably about 2.0lb/100 ft² compared to a drilling fluid composition that issubstantially the same having barite particles with a particle size of40 to 100 μm, preferably 40 to 80 μm, preferably 40 to 70 μm. However,the yield point of the drilling fluid composition at an elevatedtemperature (e.g. a temperature of 200 to 280° F., preferably 200 to250° F.) is higher by about 1.5 lb/100 ft², preferably about 2.5 lb/100ft² compared to a drilling fluid composition that is substantially thesame having barite particles with a particle size of 40 to 100 μm,preferably 40 to 80 μm, preferably 40 to 70 μm. In one embodiment, thedrilling fluid composition has a gel strength of 15 to 25 lb/100 ft²,preferably 15 to 20 lb/100 ft², preferably 15 to 18 lb/100 ft², after 10seconds, at room temperature (i.e. a temperature of 80 to 90° F.,preferably about 85° F.). The gel strength may rise to a value of 20 to25 lb/100 ft², preferably 20 to 22 lb/100 ft², after 10 minutes, at roomtemperature. Further, the gel strength may rise to a value of 20 to 25lb/100 ft², preferably 22 to 25 lb/100 ft², after 30 minutes, at roomtemperature. In view of that, the gel strength of the drilling fluidcomposition at room temperature is about the same compared to a drillingfluid composition that is substantially the same having barite particleswith a particle size of 40 to 100 μm, preferably 40 to 80 μm, preferably40 to 70 μm.

In one embodiment, the drilling fluid composition has a yieldpoint-to-plastic viscosity ratio (i.e. YP/PV) of 2.5 to 4.5, preferably3.5 to 4.2, preferably 3.5 to 4.0. Accordingly, the YP/PV of thedrilling fluid composition is at least two times, preferably at leastthree times larger when compared to a drilling fluid composition that issubstantially the same having barite particles with a particle size of40 to 70 μm, which has a YP/PV of 1.5 to 2.0.

In one embodiment, the drilling fluid composition has a density of 12 to14 ppg (pounds per gallon), preferably 12 to 13 ppg, preferably 12 to12.5 ppg at room temperature (i.e. a temperature of 80 to 90° F.,preferably about 85° F.). Accordingly, the density of the drilling fluidcomposition at room temperature is about the same compared to a drillingfluid composition that is substantially the same having barite particleswith a particle size of 40 to 100 μm, preferably 40 to 80 μm, preferably40 to 70 μm.

In one embodiment, the drilling fluid composition has a zeta potentialof about 55 to 65 mV, preferably about 55 to 60 mV, preferably about 60mV. Accordingly, the zeta potential of the drilling fluid composition ishigher (i.e. about 55 to 65 mV, preferably about 55 to 60 mV, preferablyabout 60 mV) than the zeta potential of a drilling fluid compositionthat is substantially the same having barite particles with a particlesize of 40 to 100 μm, preferably 40 to 80 μm, preferably 40 to 70 μm,which has a zeta potential of about 40 to 50 mV, preferably about 40 to45 mV.

In one embodiment, the drilling fluid composition further includes atleast one additive selected from the group consisting of an antiscalant,a thickener, a deflocculant, an anionic polyelectrolyte, a lubricant,and a fluid loss additive. In one embodiment, the total weight of the atleast one additive present in the drilling fluid composition is up to 10wt %, preferably up to 9 wt %, preferably up to 8 wt %, preferably up to7 wt %, preferably up to 6 wt %, preferably up to 5 wt %, preferably upto 4 wt %, preferably up to 3 wt %, preferably up to 2 wt %, preferablyup to 1 wt %, preferably up to 0.5 wt %, preferably up to 0.1 wt %,preferably up to 0.01 wt %, relative to the total weight of the drillingfluid composition.

In one embodiment, the at least one additive may be injected into thesubterranean formation as a separate component from the drilling fluidcomposition. The additive may therefore be injected into thesubterranean formation through a wellbore at a pressure of at least5,000 psi, at least 5,500 psi, at least 6,000 psi, at least 6,500 psi,at least 7,000 psi, at least 7,500 psi, but no more than 10,000 psi, inaddition to the drilling fluid composition, to fracture the subterraneanformation, or may be injected into the subterranean formation throughthe wellbore after the fracking.

In one embodiment, an antiscalant is incorporated as a part of thedrilling fluid composition. The term “antiscalant” refers to anychemical agent that prevents, slows, minimizes, and/or stops theprecipitation of scale (e.g. calcium carbonate, calcium sulfate, bariumsulfate, strontium sulfate, calcium phosphate, calcium fluoride, calciumsilicate, magnesium hydroxide, zinc carbonate, and the like) from theaqueous salt solution. Antiscalants which may be used in the presentdisclosure include, phosphine or sodium hexametaphosphate, sodiumtripolyphosphate and other inorganic polyphosphates, hydroxy ethylidenediphosphonic acid, butane-tricarboxylic acid, phosphonates, orphosphonic acids such as amino tris (methylenephosphonic acid) (ATMP),etc. carboxyl group-containing starting material acids, maleic acid,acrylic acid and itaconic acid and the like, polycarboxylic acidpolymers, sulfonated polymers, vinyl sulfonic acid, allyl sulfonic acid,and 3-allyloxy-2-hydroxy-propionic acid and other vinyl monomers havinga sulfonic acid group, or a non-ionic acrylamide monomer from the vinylcopolymer, and the like. Further, organic acids which are safe under theFDA GRAS guidelines for food production yet still effective indecomposition of carbonates found in the soils and in rock formationsmay be used. The basic principle action of organic acids on carbonatesis to cause the disassociation or the carbonate to produce the oxide andcarbon dioxide. The first group of suitable organic acids is lactic,acetic, formic, fumaric, citric, oxalic, adipic and uric. The secondgroup of suitable organic acids is the carboxylic acids, whose acidityis associated with their carboxyl group —COOH. Sulfonic acids,containing the group —SO₂OH, are relatively stronger acids. The relativestability of the conjugate base of the acid determines its acidity. Insome biological systems more complex organic acids such as L-lactic,citric, and D-glucuronic acids are formed. These use the hydroxyl orcarboxyl group. The third group of suitable organic acids is humic,sebacic, stearic, gallic, palmitic, caffeic, glyoxylic, fulvic,carnosic, anthranilic, ellagic, lipoic, chlorogenic, rosmarinic,phosphoric, methacrylic, oleanic, nitrohumic, florocinnamic,hexaflorosilicic, hydrofluoric, hydroxycitric and silicofluoric. Thefourth group of suitable organic acids is fruit acids. The acids infruits are chiefly acetic, malic, citric, tartaric, oxalic, and in someinstances boric. Malic acid is present in apples, pears, currants,blackberries, raspberries, quince, pineapple, cherries, and rhubarb.Citric acid is found in lemons, oranges, grapefruit,lemons, limes,quince, gooseberry, strawberry, raspberry, currant, and cranberry.Tartaric acid occurs in grapes. Boric acid is found in many fresh fruitsand vegetables. Mandelic acid is present in almonds. The fifth group ofsuitable organic acids is beta hydroxy acids which is a type of phenolicacid. Salicylic acid is a colorless crystalline organic acid whose mainactive ingredient obtained from this source is a monohydroxybenzoicacid.

In one embodiment, a thickener is present in the drilling fluidcomposition. Various thickeners may be used to influence the viscosityof the fluid, and exemplary thickeners include xanthan gum, guar gumglycol, carboxymethylcellulose, polyanionic cellulose (PAC), or starch,and mixtures thereof.

A deflocculant may also be incorporated into the drilling fluidcomposition. A deflocculant is a chemical additive to prevent a colloidfrom coining out of suspension or to thin suspensions or slurries, andmay be used to reduce viscosity of clay-based fluids. One type ofdeflocculant is an anionic polyelectrolyte, such as acrylates,polyphosphates, lignosulfonates (Lig), or tannic acid derivates such asQuebracho.

In one embodiment, the drilling fluid composition also includes alubricant, such as an oil, for lubrication and fluid loss control. Thelubricant may be a synthetic oil or a biolubricant, such as thosederived from plants and animals for example vegetable oils. Syntheticoils include, but are not limited to, polyalpha-olefin (PAO), syntheticesters, polyalkylene glycols (PAG), phosphate esters, alkylatednaphthalenes (AN), silicate esters, ionic fluids, multiply alkylatedcyclopentanes (MAC). Exemplary vegetable oil-based lubricants (i.e.biolubricants) that may be used in the present disclosure include canolaoil, castor oil, palm oil, sunflower seed oil and rapeseed oil fromvegetable sources, and Tall oil from tree sources, and the like.

Further, a fluid loss additive may be incorporated into the drillingfluid composition to control loss of drilling fluids into permeableformations. In addition to micronized barite particles, in one or moreof their embodiments, additional fluid loss additives may be added tothe composition including, but not limited to, starch, xanthan gum,guar, carboxymethyl cellulose, polysaccharides, and acrylic polymerssuch as polyacrylamide. In one embodiment, the fluid loss additive isadded in an amount necessary to achieve the desired fluid loss control,preferably less than 5 wt %, preferably less than 4 wt %, preferablyless than 3 wt %, preferably less than 2 wt %, preferably less than 1 wt%, relative to the total weight of the drilling fluid composition.

The drilling fluid composition may also include a weighting agentbesides the micronized barite particles to increase the overall densityof the drilling fluid so that sufficient bottom hole pressure can bemaintained thereby preventing an unwanted (and often dangerous) influxof formation fluids. Exemplary weighting agents include sodium sulfate,calcium carbonate (chalk), hematite, siderite, ilmenite, and anycombination thereof. The weighting agent may be added to the prepareddrilling fluid composition without adversely affecting its stability orother properties. In view of this embodiment, if one or more weightingagents are present in the drilling fluid composition besides themicronized barite particles, the one or more weighting agents preferablyhave a mean particle size in the range of 1 to 5 μm, preferably 1 to 4μm, preferably 1 to 3 μm. In another embodiment, a weight ratio of themicronized barite particles to the one or more weighting agents is atleast 2, preferably at least 3, preferably at least 4, preferably atleast 5, preferably at least 6, preferably at least 7, preferably atleast 8, preferably at least 9, preferably at least 10, preferably atleast 15, preferably at least 20, but no more than 50.

According to a second aspect, the present disclosure relates to a methodof making micronized barite particles, involving stirring a suspensionsolution comprising a barite mixture and at least one chelating agent.In one embodiment, the suspension solution is centrifugally stirred(e.g. using a centrifugal mixer or an agitator, as shown in FIG. 1) witha rotational speed of at least 500 rpm, preferably at least 600 rpm,preferably at least 800 rpm, but no more than 2000 rpm, for at least 1hour, preferably at least 2 hours, but no more than 3 hours. Preferably,the suspension solution is stirred at a temperature in the range of 40to 80° C., preferably 40 to 70° C. This temperature may be provided by aheating jacket or a hot plate (as shown in FIG. 1).

The “barite mixture” as used herein refers to a solid mixture thatincludes barium sulfate (barite) and impurities such as sodium sulfate,aluminum oxide, manganese tetraoxide, potassium formate, hematite,siderite, ilmenite, cement, pyrrhotite, gypsum, anhydrite, calciumcarbonate, and the like. In a preferred embodiment, an amount of baritein the barite mixture is at least 80wt %, preferably at least 90wt %,preferably at least 95wt %, preferably at least 99wt %, relative to thetotal weight of the barite mixture.

In a preferred embodiment, the method further involves grinding thebarite mixture prior to the stirring, followed by sieving ground baritemixture, classifying the ground barite mixture into a class of particleswith a particle size of greater than 50 μm, a class of particles with aparticle size of 20 to 50 μm, and a class of particles with a particlesize of smaller than 20 μm.

In another preferred embodiment, the method further involves treatingthe barite mixture with a leaching acid prior to the stirring, to leachand remove acid-soluble impurities from the barite mixture. In oneembodiment, the leaching acid is a mineral acid selected from the groupconsisting of hydrochloric acid and/or sulfuric acid.

The “chelating agent” as used herein refers to a chemical used to bindmetal ions to form a ring structure. The chelating agent may stabilizethe suspension solution by preventing the precipitation of at least aportion of the impurities of the barite mixture. Preferably, thechelating agent may not interact with the barite particles; however, thechelating agent interacts with at least a portion of the impurities inthe suspension solution. In view of that, barite particles preferablyprecipitate, whereas those impurities, which interact with the chelatingagent, may stabilize and remain in a soluble form in the suspensionsolution until the chelating agent is removed from the suspensionsolution, leaving behind the barite particles and other impurityparticles that are insoluble in the chelating agent. In one embodiment,the barite particles and impurity particles have a mean particle size inthe range of 1 to 80 μm, preferably 1 to 70 μm, preferably 1 to 60μpreferably 1 to 50 μm.

The chelating agent may have a pH of at least 10, preferably at least11. In view of the pH of the chelating agent, the suspension solutionmay have a pH in the range of 7 to 14, preferably 10 to 12.

In a preferred embodiment, the chelating agent is at least one selectedfrom the group consisting of EDTA (ethylenediamine tetraacetic acid),GLDA (glutamic diacetic acid), and HEDTA (hydroxyethylenediaminetriacetic acid), and salts thereof. Further to these chelating agents,one or more chelating agents may also be added to the suspensionsolution selected from the group consisting of NTA (nitriolotriaceticacid), DTPA (diethylenetriaminepentaacetic acid), MGDA(methylglycinediacetic acid), HEIDA (2-hydroxyethyliminodiacetic acid),CDTA (trans-cyclohexane-1,2-diaminetetraacetic acid), EGTA (ethyleneglycol-bis((β-aminoethyl ether)-N,N,N′,N′-tetraacetic acid), EDDA(ethylenediaminediacetic acid), and salts thereof.

The amount of the chelating agent in the suspension solution may varydepending on the type of the chelating agent and the amount of barite inthe barite mixture. For example, in one embodiment, the amount of baritein the barite mixture is at least 80wt %, preferably at least 85wt %,but no more than 90wt %. In view of that, the amount of the chelatingagent in the suspension solution is in the range of 5wt % to 20 wt %,preferably 5wt % to 15wt % when the chelating agent is EDTA, whereas theamount of the chelating agent in the suspension solution is in the rangeof 5wt % to 20wt %, preferably 10wt % to 20wt % when the chelating agentis GLDA. In another embodiment, the amount of barite in the baritemixture is at least 95wt %, preferably at least 99wt % (such as thelocal Saudi barite). In view of that, the amount of the chelating agentin the suspension solution is in the range of 1wt % to 10wt %,preferably 1wt % to 5wt %, when the chelating agent is EDTA, whereas theamount of the chelating agent in the suspension solution is in the rangeof 1 wt % to 10wt %, preferably 5wt % to 10wt % when the chelating agentis GLDA. Each weight percent of the chelating agent is relative to thetotal weight of the suspension solution, whereas each weight percent ofthe barite particles is relative to the total weight of the baritemixture.

The method further involves filtering the suspension solution to form afilter cake comprising the barite particles and impurity particles thatare insoluble in the chelating agent. “Filtering” is used herein toseparate the barite particles from impurity particles that are solublein the chelating agent. Therefore, “filtering” as used herein, refers toa process of removing the chelating agent from the suspension solution,whereby impurity particles that interact with the chelating agent leavethe suspension solution, leaving behind the filter cake. Accordingly,the filter cake preferably refers to dry particles including bariteparticles and impurity particles that are insoluble in the chelatingagent. In a preferred embodiment, the filter cake includes at least 80wt%, preferably at least 85wt %, preferably at least 90wt %, preferably atleast 95wt %, preferably at least 99wt % of barite particles with aparticle size in the range of 1 to 80 μm, preferably 1 to 70 μm,preferably 1 to 60 μm, wherein less than 20wt %, preferably less than15wt %, preferably less than 10 wt %, preferably less than 5wt %,preferably less than 1wt % of the filter cake includes impurityparticles that are insoluble in the chelating agent.

In one embodiment, the impurity particles that are insoluble in thechelating agent (e.g. hematite, siderite, ilmenite, cement, pyrrhotite,gypsum, anhydrite, calcium carbonate, etc.) may precipitate on top ofthe barite particles (as shown in FIG. 1), after the chelating agent isremoved from the suspension solution. Therefore, the impurity particlesmay be removed before grinding the barite particles. Preferably, theimpurity particles do not include barite particles (as barite particlesmay precipitate first and the impurity particles may precipitatethereafter), and thus can be removed, for example, by pumping.

The method further involves grinding the filter cake to form themicronized barite particles each having a particle size in the range of1 to 5 μm, preferably 1 to 4 μm, preferably 1 to 3 μm. Preferably,“grinding” may be performed after removing the impurity particles fromthe filter cake, although “grinding” may also be performed withoutremoving the impurity particles when the amount of impurity particles inthe filter cake is less than 5wt %, preferably 1 wt %. The filter cakemay be air-dried before grinding. Accordingly, the filter cake isexposed to an air stream at a temperature in the range of 80 to 90° F.,preferably about 85° F., for at least 12 hours, preferably at least 24hours.

Grinding the filter cake may be performed using a ball-miller or aroll-miller. In a preferred embodiment, the micronized barite particlesare sieved after the grinding, and as a result the micronized bariteparticles may not contain barite particles with a particle size largerthan 10 μm, preferably 5 μm. However, the micronized barite particlesmay include barite particles having a particle size smaller than 1 μm.

The examples below are intended to further illustrate protocols forpreparing and characterizing the micronized barite particles and thedrilling fluid composition, and are not intended to limit the scope ofthe claims.

EXAMPLE 1

In the below examples, a method of producing local Saudi barite inmicronized size (1 to 5 micron) is introduced. Local Saudi barite existsin huge quantities in several areas, its purity ranges between 88 to99%. Impurities such as calcium fluoride, quartz, and calcium carbonatecould be contaminated in the barite in these sources. In this inventionwe will provide a method that can target both pure and impure barite.For the pure one the target will be producing micron size and the targetfor the impure one will be to remove the impurities and producing it inmicron size. The current available industrial grade barite is in 40 to70 micron size. We proved that the micronized size of the Saudi baritewill make more stable drilling and completion fluid and also willenhance the removal and cleaning processes. Local Saudi barite exists inhuge amounts and most of this barite is not clean, it contains someimpurities such as quarts and calcite. In this invention we introduce asingle step method that will remove the impurities and produce themicronized size of the Saudi Barite.

EXAMPLE 2

Two types of Saudi barite, i.e. the pure and impure one, have beendiscussed here. For the pure barite the objective will be to decreasethe size to 1 to 5 micron by mixing the grinded barite with thefollowing chelating agents; 1 to 5 wt % EDTA, and 5 to 10% GLDA attemperature range of 40 to 70° C. The mixture should be stirred at highrpm after that the solution can be filtered and the barite size will bereground again to obtain the 1 to 5 micron size.

The second type of Saudi barite is that the one contains some impuritiessuch as carbonates, quartz, and calcium fluoride. For this one thetreatment will be using the same mentioned chelating agents but withhigher concentration. The impure barite will be mixed and stirred withthe EDTA chelating agent (5 to 15 wt % concentration) or with GLDAchelating agent (10 to 20 wt % concentrations). The pH of both chelatingagents should be higher than 11. The solution will be stirred at highrpm and temperature range of 40 to 70° C. The lighter materials thoseare not soluble in chelating agent such as quartz will be separated bygravity because it will precipitate at the surface of barite. Otherimpurities will be removed by the chelating agents.

EXAMPLE 3

The following schematic shows the laboratory scale for the treatment ofthe impure local Saudi barite. FIG. 1 shows the method used in thelaboratory to upgrade the local Saudi barite to pure and micron sizeone. The sandstone content reaches 11 to 12% in certain locations fromthe XRD analysis. In the large scale the sand can be extracted bydesigning ports at the interface between the barite and quartz based onthe volume of the field treatment vessel. For example for barite purityof 89% with 11% by weight quartz (one of the samples we have treated),if 10,000 kg wanted to be treated it will contain 8900 kg barite and1100 kg sandstone. This amount can be treated in cylindrical vessel with3 m³ size. The port that should extract the quartz should be located at2 m off the bottom of the vessel.

EXAMPLE 4

Zeta potential measurements which are related to the dispersion abilityof the solids in the solution were measured for the industrial gratebarite and it was −44 mv as shown in FIG. 2. The size of the industrialgrade barite ranges between 40 and 70 micron and the size of the treatedlocal Saudi barite ranges between 1 and 5 micron.

EXAMPLE 5

The production of smaller size barite will enhance the dispersion of thebarite particles in both drilling fluids and cement slurries that areused for HPHT applications. This will prevent the problems associatedwith the drilling fluid such as the removal of the filter cake and thesagging problems. During the cementing operations in HPHT wells thecement settling problems of the cement weighting material is a commonissue which needs squeezing or a secondary treatment for that cement andthis might cause some problems in oil and gas wells. Water and gas canmigrate through the bas cement and this will cause environmentalproblems. Using the micron size in cement will enhance the stability anddispersion of the barite weighting materials in cement and eliminatecementing problems. Also the micron size barite will produce good cementsheath behind the casing with high compressive strength and zeropermeability and very low porosity. With the drilling fluid the micronbarite will enhance the stability and eliminate the sagging problem thatmight cause bit balling. Also the micron size will enhance the removalof the filter cake.

EXAMPLE 6

Micron barite will be added to the drilling fluid in sufficient amountand the proper sizing for other particles such as calcium carbonate thefinal formulation can be obtained. Micron barite will provide moresurface area available for reaction with the filter cake removal fluidand this will enhance the filter cake removal process and less fluidvolume and concertation will be used.

FIGS. 3 and 4 show the formation and removal process of the filter cakeformed by using micron barite as weighting material of the drillingfluid and the removal efficiency of the filter cake approached 93%compared to 85% with the industrial grade one.

EXAMPLE 7

The solubility of the barite using 20% DTPA chelating agent was testedusing two grades the industrial and upgraded Saudi one. FIG. 5 shows thesolubility of the barite particles in 20% DTPA at 200° F. The solubilityincreased from 60 g/100 g (for the industrial grade barite) to 70 g/100g (for the upgraded micron size local Saudi barite).

EXAMPLE 8

Laboratory experiments were conducted to compare between the local Saudibarite and commercial barite as a weighting material for water-baseddrilling fluids for deep oil and gas wells. As a result, we observedthat:

-   -   At room temperature, the two samples yielded very close        properties.    -   At higher temperature, the Saudi local barite yielded a lower        plastic viscosity and higher yield point compared to the        commercial barite which is very important in hole cleaning and        reducing the annular pressure losses during the drilling fluid        circulation and this will save the pumping requirements.    -   The YP/PV for local Saudi barite was 3.7 and with 1.8 for        commercial barite at 250° F. This make the Saudi barite better        in terms of hole cleaning than the commercial one.

EXAMPLE 9 Water-Based Drilling Fluid Formulation

Table 1 lists the composition of the water-based drilling fluid, whichcontains water as the base phase, KOH to adjust the pH, bentonite (4 g)as a viscosifier, xanthan gum (1 g) for viscosity and fluid losscontrol, KCl (20 g) for shale stabilization, calcium carbonate as abridging material, and Barite as a weighting material.

Two different samples of the drilling fluid were prepared. One samplecontains the Saudi local barite and the other one contains commercialbarite. The properties were measured at room temperature.

TABLE 1 Water-based drilling fluid composition. Local CommercialComponent Unit Sample Sample Water g 245 245 Soda ash g 0.5 0.5 KOH g0.5 0.5 Bentonite g 4 4 XC-polymer g 1 1 KCl g 20 20 CaCO3 medium g 5 5Barite g 200 200 Sodium sulfide g 0.25 0.25

EXAMPLE 10 Drilling Fluid Properties

At room temperature, both the formulations yielded very close results aslisted in Table 2. The density 12.51 and 12.31 lb/gal was obtained forcommercial and local barite sample, respectively. FIG. 6 shows therheometer reading at different shear rates (rpm). It is clear that athigh shear rates the two samples behaved the same, which can bedescribed by Bingham plastic behavior.

TABLE 2 Drilling Fluid Properties at room Temperature. PropertyCommercial Barite Local Barite Density, ppg 12.51 12.31 pH 10.7 10.6Plastic Viscosity, cP 13 16 Yield Point, lb/100 ft² 40.5 38.5 Gel 10sec, lb/100 ft² 15 15 Gel 10 min, lb/100 ft² 20 20 Gel 30 min, lb/100ft² 25 25

To evaluate the behavior at higher temperatures, the two samples wereheated using HPHT rheometer to 200° F. and 250° F. under a pressure of300 psi. Table 3 lists the dial reading at different temperature for thetwo samples.

FIG. 7 shows the change in plastic viscosity with increasing thetemperature for both samples. At higher temperature, 250° F., the localbarite yielded low plastic viscosity compared to the commercial baritewhich indicated lower annular pressure needed to lift the fluid to thesurface. As a result, reducing the equivalent circulation density andreducing the possibility of fluid losses and formation fracture.

FIG. 8 shows that the yield point of the local barite sample is higherthan the yield point of the commercial barite sample which will enhancethe carrying capacity of the drilling fluid and hence enhance the holecleaning and improve the drilling rate. The YP/PV ratio for local Saudibarite was 3.7 as compared with 1.8 for commercial barite at 250° F.

TABLE 3 Rheometer reading for local and commercial samples at differenttemperature. Room temperature φ 200° F. φ 250° F. φ TemperatureCommercial Local Commercial Local Commercial Local N Barite BariteBarite Barite Barite Barite 3 14 33 6.6 17 7.3 15 6 16 35 8.6 18.7 8.717.5 100 35.5 41.5 18.8 20 19.3 20 200 46.5 48.5 24 22.7 24.2 22.2 30053.5 54.5 27.3 25.3 28 24.2 600 66.5 70.5 37.8 32.2 38.1 29.3

EXAMPLE 11 Advantageous of Local Micronized Barite over the CommercialBarite

-   -   The local barite has lower plastic viscosity at higher        temperatures; higher temperatures means deep wells and this will        lower the equivalent circulating drilling fluid density and will        lower the possibility of lost circulation and formation        fractures.    -   The local barite drilling fluid has Yield point/plastic        viscosity ratio greater than that for the commercial one which        makes the local barite better in terms of hole cleaning. Hole        cleaning increases with increasing the ration of YP/PV.        Enhancing the hole cleaning will increase the drilling        efficiency, and rate of penetration and in turn will lower the        drilling cost.

1: A method of fracturing a subterranean formation, comprising: injecting a drilling fluid composition into the subterranean formation through a wellbore to fracture the subterranean formation and form fissures in the subterranean formation, wherein the drilling fluid composition comprises: micronized barite particles with a particle size in the range of 1 to 5 μm; an aqueous base fluid; and a viscosifier, wherein the micronized barite particles are present in the drilling fluid composition at a concentration in the range of 1 wt % to 50wt %, relative to the total weight of the drilling fluid composition. 2: The method of claim 1, further comprising: injecting a proppant into the subterranean formation through the wellbore to deposit the proppant in the fissures. 3: The method of claim 1, further comprising circulating the drilling fluid composition within the wellbore after the injecting. 4: The method of claim 1, wherein the drilling fluid composition is injected at a pressure of at least 5,000 psi to fracture the subterranean formation. 5: The method of claim 1, wherein the viscosifier is bentonite. 6: The method of claim 1, wherein the drilling fluid composition has a plastic viscosity of 14 to 18 cP at a temperature of 80 to 90° F. 7: The method of claim 1, wherein the drilling fluid composition has a plastic viscosity of 4.5 to 7.0 cP at a temperature of 200 to 280° F. 8: The method of claim 1, wherein the drilling fluid composition has a density of 12 to 14 ppg at a temperature of 80 to 90° F. 9: The method of claim 1, wherein the drilling fluid composition has a yield point of 35 to 45 lb/100 ft² at a temperature of 80 to 90° F. 10: The method of claim 1, wherein the drilling fluid composition has a gel strength of 15 to 25 lb/100 ft² at a temperature of 80 to 90° F., after 10 seconds. 11: The method of claim 1, wherein the drilling fluid composition has a yield point-to-plastic viscosity ratio of 2.5 to 4.5. 12: The method of claim 1, wherein the drilling fluid composition has a zeta potential of 55 to 65 mV. 13: The method of claim 1, wherein the drilling fluid composition further comprises: at least one additive selected from the group consisting of an antiscalant, a thickener, a deflocculant, an anionic polyelectrolyte, a lubricant, and a fluid loss additive. 14: The method of claim 1, wherein a solubility of the micronized barite particles in the aqueous base fluid is at least 70 g/100 g at a temperature of 150 to 250° F. 15: A method of making micronized barite particles, comprising: stirring a suspension solution comprising a barite mixture and at least one chelating agent; filtering the suspension solution to form a filter cake comprising barite; and grinding the filter cake to form the micronized barite particles each having a particle size in the range of 1 to 5 μm, wherein an amount of barite in the barite mixture is at least 80wt %, and wherein an amount of said chelating agent in the suspension solution is in the range of 1wt % to 20wt %, relative to the total weight of the suspension solution. 16: The method of claim 15, further comprising: grinding the barite mixture prior to the stirring. 17: The method of claim 15, wherein the suspension solution is centrifugally stirred with a rotational speed of at least 500 rpm, at a temperature in the range of 40 to 80° C. 18: The method of claim 15, wherein the amount of barite in the barite mixture is at least 95wt %, and wherein the amount of said chelating agent in the solution is in the range of 1wt % to 10wt %. 19: The method of claim 15, wherein said chelating agent is at least one selected from the group consisting of ethylenediamine tetraacetic acid, glutamic diacetic acid, hydroxyethylenediamine triacetic acid, and salts thereof. 20: The method of claim 15, wherein the suspension solution has a pH in the range of 7 to
 14. 